Corrosion sensors are used in the detection and monitoring of loss of material, such as the internal surface of a pipeline wall, due to corrosion and/or erosion from interaction between the material and the environment in contact with the material. Such conditions exist in oil or gas pipelines.
Commonly, corrosion sensors use electrical resistance methods to detect loss of material due to corrosion/erosion. Such a corrosion detector system includes using the principles of electrical resistance to determine corrosion/erosion of a pipeline wall surface. Such a system consists of measuring the thickness of the pipeline wall with pick-up points along the external surface of a pipeline section. The pipeline section is energised by a longitudinal current applied at two points adjacent to either side of the pick-up area. The current density map through the material, proportional to wall thickness, is derived by measurement of voltages across the matrix of pick-up points relative to an external reference, and the resistive ratios are converted into the metal loss.
The sensitivity of such prior art corrosion detector arrangements is limited by various factors. For instance, the sensitivity of the corrosion detector arrangement is dependant on the maximum current which can be sustained. The maximum current is limited for intrinsically safe applications in potentially explosive environments such as in oil and gas pipelines. In such corrosion detector systems, sensitivity is also limited by the very small measured resistive voltages between array pick-up points. Disturbances such as noise and dc offsets occurring in the electronic circuitry of the corrosion detector systems and thermoelectric voltages and electromagnetic noise in the leads make high-resolution measurements of such small voltages difficult.
Additionally, changes in the temperature in the environment in which pipeline is situated changes the electrical resistance of the pipe. For example, the resistance of steel may change by 0.4% per ° C. In electrical resistance corrosion monitoring systems configured with an element having an exposed surface to the environment and a reference system external to the environment such as the pipeline fluid environment, changes in fluid temperatures significantly limit the accuracy and sensitivity of the monitoring system if the temperature of the pipeline and external reference system differ. To illustrate, a nominal difference in temperature of 0.25° C. between the pipeline and reference system will cause a change in the resistance ratio of 1000 ppm.
Furthermore, the circumferential and radial temperature excursions may be present around the profile of the pipeline. This will depend on the pipeline process fluid conditions and the location of the pipeline itself. For example, the fluid environment may comprise a cross-sectional layered profile of water, crude oil, and gas. The boundary phases between these layers may also change over time. A difference of 0.25° C. between the top and bottom of the pipeline would cause a further change in the resistance ratio of about 1000 ppm.
The hydrostatic and thermal stresses induced in pipeline structures will also influence the measured resistive voltages. In prior art corrosion detector arrangements with a reference system external to the fluid environment, the reference system will not be subjected to the hydrostatic and thermal loads and therefore further errors will occur.
The mechanisms involved in the change of resistance due to strain are extremely complex and not easily predicted. Change in resistance due to strain relates to the distortion of the lattice structure, which varies according to material composition and microstructures. Although the affects are much less than temperature, typical pipeline steels exhibit changes of between 2000–4000 ppm per 100 BAR of pressure or 20–40 ppm per BAR. Of course, in prior art corrosion monitoring with an external reference system, the external reference system is not subject to the changing internal pressure of the pipeline and the external reference system is not subject to the resultant changing resistive voltages. This contributes to further errors.
Similarly, as temperature change occurs there will be subsequent residual thermal stresses induced, resulting in further change in the resistive voltages. In addition, it is apparent that under a pressurised system the change in wall thickness due to corrosion and/or erosion will result in an increase in radial and circumferential stress distributions through the pipe wall. This will in turn induce further unwanted change to the measured resistive voltages.
The cumulative effect of resistive voltage changes due to changes of in process conditions not adequately compensated by the referencing system could result in expected deterioration of resolutions in excess±4000 ppm, for a temperature difference between pipeline and external reference system of 1° C. and a pressure difference of 100 BAR. With additional errors expected due to profile temperature and stress effects.
Therefore, there is a need for an electrical resistance corrosion monitor with a greater sensitivity to accurately measure at a higher resolution, the corrosion and/or erosion of a pipeline in a corrosive/erosive environment, especially where the environment temperature and/or hydrostatic pressure may be fluctuating.